In typical oil and/or gas rotary drilling operations, a turntable on the floor of a drilling rig rotates a string of hollow steel drill pipes at the bottom of which is a rotary drill bit. The bit grinds the rock as it is rotated by the drill pipe. A drilling fluid is pumped clown through the drill pipe that flushes out the rock cuttings from the bit face and lubricates the bit and then returns up the annular space between the drill string and the sidewalls of the bore being drilled. The drilling fluid or mud cools and lubricates the bit, carries the drill cuttings from the hole to the surface and cakes the wall of the hole to prevent caving before steel casing is set. The hydrostatic pressure exerted by the column of mud in the hole prevents blowouts that may result when the bit penetrates a high pressure oil or gas zone. Thus the weight in pounds per gallon (ppg) of the drilling fluid must be sufficiently high to prevent blowouts, but not high enough to enter into formation rocks such as where unconsolidated sections exist or by causing fracturing of the formation. In other words, if the mud pressure is too low, the formation fluid can force the mud from the hole, resulting in a blowout, whereas if the mud pressure becomes too high, the differential pressure becomes great enough that mud flows into the formation and/or the rock adjacent to the well may be fractured, resulting in lost circulation. Herein, lost circulation or lost returns is defined as the loss to formation voids of the drilling fluids used in rotary drilling. This loss may vary from a gradual lowering of the mud level in the pits to a complete loss of returns. The loss of drilling mud and cuttings into the formation results in slower drilling rates and plugging of productive formations. When circulation suddenly diminishes, the drilling rate or rate of penetration (ROP) must be scaled back as the mud flow rate is reduced. Moreover, losing mud into productive formations can severely damage the formation permeability, lowering production rates therefrom. Such plugged formations must often be subjected to costly enhanced recovery techniques in an effort to restore the formation permeability to raise production rates back up to their former levels. In addition to slower drilling and lowered production rates, Is the chemicals used in drilling mud can be fairly expensive, the loss of the drilling mud itself to the formation is also economically undesirable.
Optimizing the drilling fluid hydraulics for proper flow and circulation where the mud sweeps the bottom-hole surface free of cuttings, entrains the bit cuttings and carries them to the surface is important for drilling efficiency reducing rig down time for tripping to replace prematurely worn drill bits. In this regard, it is important to consider both the design of the bit and the various sources of pressure or energy losses within the circulatory systems. More particularly, the return velocity of the mud in the annular space between the drill pipe and bore hole walls must be maintained at a rate sufficient to extract the bit cuttings and carry them up to the surface despite the frictional losses encountered in the annular space. The pressure or head losses in the drilling fluid in the annulus between the drill pipe and bore is generally low due to the relatively large size of the annular space that maintains substantially laminar flow of mud therethrough because of the difference in diameters between the larger diameter of the hole or bit size in comparison to the smaller diameter drill pipe. In any event, the frictional losses on the circulating mud system should be considered for determining the fluid pressure requirements at the pump to obtain desired mud flow rates and return velocities. If the drilling fluid pressure at the bottom of the bore hole is too high, it impedes the drilling action of the bit. Rock failure strength increases, and the failure becomes more ductile as the pressure acting on the rock is increased. Ideally, cuttings are cleaned from beneath the bit by the drilling fluid stream. However, relatively low differential mud pressure tends to hold cuttings in place. In this case, mechanical action of the bit is often necessary to dislodge the chips. Regrinding of the fractured rock can greatly decrease drilling efficiency by lowering the drilling rate and increasing bit wear. In extreme conditions, the rock can be ground to a fine dust that can agglomerate and re-cement onto the bit preventing effective cutting. Such recementing is termed "balling."
The drill string usually consists of 30-foot lengths of relatively small diameter drill pipe (e.g. 5 in. O.D.) coupled together. On the lower end are heavier-walled lengths of pipe, called drill collars, that help regulate weight on the bit. When the bit has penetrated the distance of a pipe section, drilling is stopped, the string is pulled up to expose the top joint, a new section added, the string lowered and drilling resumed. The process continues until the bit becomes worn out, at which time the entire drill string must be pulled. Pipe is usually disconnected in triples or 90-foot sections of pipe, and stacked in the derrick. The process continues until the bit reaches the surface. A new bit is attached, and the drilling string reassembled and lowered into the hole. Such round trips may take up to two-thirds of total rig operating time, depending on the depth of the hole. It is desirable to increase both bit life and drilling rates simultaneously to minimize drilling time. Where the bit has high wear rates requiring increased number of trips into and out of the wellbore, or where complex lithologies exist such as requiring drilling through an unstable or depleted formation with attendant well bore stability and/or loss of circulation problems, the rig time can become very expensive in relation to the anticipated production from the well.
Thus, drilling costs depend on the cost of such items as the drilling rig, the bits, and the drilling fluid, as well as on the drilling rate, the time required for tripping to replace a worn bit, and bit life. The cost-per-foot generally increases with depth when encountering geopressures, heavy shale, lost circulation, and well consolidated hard formations such as hard limestone stringers.
Normally, once a wellbore has been drilled, it is lined or cased with heavy steel piping, and the annulus between the wellbore and casing is filled with cement. Properly designed and cemented casing prevents collapse of the wellbore and protects fresh water aquifers above the oil and gas reservoir from becoming contaminated with oil and gas and the oil reservoir brine. Similarly, the oil and gas reservoir is prevented from becoming invaded by extraneous water from aquifers that penetrated above the productive reservoirs. The total length of casing of uniform outside diameter that is run in the well during a single operation is called a casing string. The casing string is made up of joints of steel pipe that are screwed together to form a continuous string as the casing is extended into the wellbore. There are three principal types of casing strings, the classification being based on the primary function of the string. The surface string protects the fresh water sand. In deep wells, one or more intermediate strings of casing are set in order to cement off either high pressure intervals that cannot be controlled by the weight of the drilling fluid, or low pressure intervals into which large volumes of drilling mud may flow and result in lost circulation, preventing further controlled drilling, as previously described. The oil or production string is the member through which the well is completed, produced, and controlled. The casing size should be of a relatively large diameter where it is anticipated that multizone completions are a possibility, workovers will be necessary, or drilling conditions will necessitate one or more intermediate strings. However, large diameter holes and casings increase the costs associated with the drilling and completion of a wellbore.
As discussed above, the casing, together with the cement, performs the following functions, namely to (1) prevent caving of the hole, (2) prevent contamination of fresh water in the upper sands, (3)exclude water from the producing formation, (4) confine production to the wellbore, (5) provide means for controlling pressure, and (6) facilitate installation of any anticipated subsurface equipment that may be necessary. In selecting casing, the engineer must consider the forces to which the casing will be subjected including external pressure, internal pressure, and a longitudinal or axial loading on the casing. External pressure, such as caused by differential pressures between adjacent formations, tends to collapse the casing, and internal pressure tends to burst the casing. Axial loading may be tension due to dead weight or compression due to buoyancy. Axial tension has two pronounced effects: it tends to pull the casing apart, and it lowers the resistance of the casing to collapse from external pressures. In addition, as the individual lengths of casing are usually joined by means of threaded couplings, it is important that they have sufficient strength to resist rupture or deformation under the axial stresses to which they will be subjected. Also, they must be leak-resistant in tension if the casing string is to perform its functions properly.
A liner is an abbreviated oil casing string that generally extends from the bottom of the hole upward to a point approximately 300 feet above the lower end of the protection string, where it is suspended from a liner hanger and sealed off. Its function is similar to that of an oil casing string such that it must have similar physical characteristics. Its obvious advantage over a conventional string that would extend from the bottom of the hole to the surface is economy, since less pipe is needed for a liner. Similar to casings, when selecting a liner, it is important to consider the external and internal pressure and axial loading forces it must withstand.
As previously mentioned, drilling challenges occur due to formation lithology where drilling must proceed through unstable or depleted formations such as through low pressure reservoirs, such as around old producers, or through unconsolidated reservoirs, such as salt domes that create wellbore stability problems. Typical drilling methods in dealing with these situations include drilling with drill string to within a few meters of the unstable or depleted reservoir, tripping the drill string out of the hole and running casing to bottom and setting it in cement in an effort to isolate as much of the overburden as possible so as to minimize the negative effects of lost returns. Nevertheless, once the remainder of the overlying reservoir is drilled and the unstable or depleted reservoir is penetrated, the differential pressure will still cause the weighted mud system to be influxed into the low pressure formation that plugs up the formation. Another method is to drill until the bottom of the hole "falls out", remove the drill pipe from the hole, and seal off the losses with a so-called "gunk pill" or cement plug. Casing is then run into the bore to the top of the loss zone where the reservoir is drilled with a reduced mud weight to prevent further losses. Neither of these methods is satisfactory due to the time required for pulling the drill pipe and the losses of the weighted mud, gunk squeezes, and cement to the production zone.
Based on the above, it is apparent that there are a number of significant engineering decisions that must be made when designing a wellbore drilling and completion program in an effort to maximize returns from a particular well. These decisions can be critical, especially where rig time is very expensive, e.g., offshore drilling, and where complex lithologies exist. It is always important to minimize the time required to properly drill and complete a wellbore so that profitable production can begin with no undue delays. One area that is constantly under scrutiny is the time it takes to trip in and out of the wellbore and how often this occurs for a given amount of depth that is drilled. Accordingly, one method of drilling that has been proposed is to use the casing as drill pipes to drill the bore hole to save rig time for running casing into the hole after drilling. However, applicants have found that the use of a casing for drilling is not without problems primarily due to the larger size of casing with respect to the drill string that creates a smaller sized annulus. These problems range from tight hole or stuck pipe concerns to the proper drill bit selection and design and ensuring good fluid hydraulics for the mud. Moreover, casing is not normally subjected to torquing forces like a drill pipe, so that where the casing is rotated for rotating the bit, the torque forces on the casing can create problems that normally are not considered.
Where the hole has to be enlarged for fitting large diameter piping into the hole, the use of expandable underreamers are known to allow the bit to be run through a hole having a smaller diameter than it will cut. Typically, once drilling with the underreamer bit is completed, the arms of the reamer are collapsed and it is retrieved from the bore and the casing is set in cement. With the underreamer pulled from the bore, drilling can continue beyond the casing if necessary to extend the bore deeper into additional underlying producing formations. However, the additional time required to pull the bit for subsequent drilling beyond the liner is undesirable.
Another bit known for making enlarged holes is a bi-center bit where sets of cutters are mounted eccentrically with respect to the central axis of the bit. However, normal bi-center bits have been found to be unstable and more readily undergo harmful bit vibration when rotated with their asymmetric design, and accordingly, their use is not favored as it is difficult to control the bore being drilled and the cutters thereon tend to break from the bit. In addition, using bi-centers rigidly fixed on casings is not done. One problem with this is that fixed bits can not be pulled back through the casing once drilling is complete, thus rendering subsequent drilling beyond the casing bottom more difficult. Accordingly, there is a need for a cost-effective method and drilling assembly that allows unstable or depleted formations to be drilled and controlled against wellbore stability problems and fluid loss to the formation. Further, there is a need for an improved drilling method and assembly that allows for the use of a casing or liner pipe such as in drilling into unstable or depleted formations that minimizes pipe hang-up problems and provides for satisfactory fluid hydraulics.